Systems and methods for producing hydrocarbons from hydrocarbon bearing rock via combined treatment of the rock and subsequent waterflooding

ABSTRACT

A method for producing hydrocarbons within a reservoir includes (a) injecting an aqueous solution into the reservoir. The aqueous solution includes water and a thermally activated chemical species. The thermally activated chemical species is urea, a urea derivative, or a carbamate. The thermally activated chemical agent is thermally activated at or above a threshold temperature less than 200° C. In addition, the method includes (b) thermally activating the thermally activated chemical species in the aqueous solution during or after (a) at a temperature equal to or greater than the threshold temperature to produce carbon-dioxide and at least one of ammonia, amine, and alkanolamine within the reservoir. Further, the method includes (c) increasing the water wettability of the subterranean formation in response to the thermally activation in (b). Still further, the method includes (d) waterflooding the reservoir with water after (a), (b) and (c).

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.15/543,527 filed Jul. 13, 2017, which is a 35 U.S.C. 371 national stageapplication of PCT/US2016/013059 filed Jan. 12, 2016, which claimspriority to U.S. provisional patent application Ser. No. 62/102,713filed Jan. 13, 2015, and entitled “Systems and Methods for ProducingHydrocarbons from Hydrocarbon Bearing Rock via Combined Treatment of theRock and Waterflooding,” each of which is hereby incorporated herein byreference in its entirety for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

FIELD

Embodiments described herein generally relate to methods for recoveringhydrocarbons from hydrocarbon bearing rock (e.g., subterraneanformations). More particularly, embodiments described herein relate tomethods for modifying the wettability of the hydrocarbon bearing rock toenhance recovery of the hydrocarbons during a subsequent waterflood.

BACKGROUND

In many reservoirs, the original oil-in-place (OIP) is recovered inmultiple stages. In an initial stage, usually termed “primary”production, the intrinsic reservoir pressure is sufficient to drive theoil from the subterranean reservoir into the production. Usually, only afraction of the original OIP is produced by this method—often, up toabout 20% of the original OIP is produced. The next stage of production,usually termed “secondary” production, relies on alternative productiontechniques (other than the intrinsic reservoir pressure) to recover moreof the original OIP.

Waterflooding is one type of secondary recovery technique that employs aplurality of wells drilled into the reservoir. The wells may include aplurality of horizontally-spaced vertically oriented wells drilled intothe reservoir and/or a plurality of horizontally-spaced horizontallyoriented wells drilled into the reservoir. Water is injected underpressure into the reservoir through one or more of the wells, eachreferred to as an “injection” well. The water increases the reservoirpressure, and as the water moves through the formation, it displaces oilfrom the pore spaces. The displaced oil is pushed or swept through theformation and into one or more of the other wells, each referred to as a“production” well. The hydrocarbons and any water collected in theproduction wells are produced to the surface via natural flow orartificial lift (i.e., with or without artificial lift). Waterfloodingcan be used to recover additional oil, often up to an additional 30% ofthe original OIP. After this point, the cost of continuing a waterfloodoften becomes uneconomical relative to the value of the oil produced.Hence, as much as 50% of the original OIP can remain in the reservoirafter a reservoir has been extensively waterflooded. In general,waterflooding is used as a recovery technique for light oil (32°-40° APIgravity), medium oil (20°-32° API gravity), and some viscous oils suchas heavy oil (less than 22° API gravity) and bitumen (less than 10° APIgravity).

Thermal recovery techniques are particularly suited for recoveringviscous oil such as heavy oil and bitumen. These techniques utilizethermal energy to heat the hydrocarbons, decrease the viscosity of thehydrocarbons, and mobilize the hydrocarbons within the formation,thereby enabling the extraction and production of the hydrocarbons. Asteam-assisted gravity drainage (SAGD) operation is one exemplary typeof thermal technique for recovering viscous hydrocarbons. SAGDoperations typically employ two vertically spaced horizontal wellsdrilled into the reservoir and located close to the bottom of thereservoir. Steam is injected into the reservoir through the upper,horizontal well, referred to as the “injection” well, to form a “steamchamber” that extends into the reservoir around and above the horizontalinjection well. Thermal energy from the steam reduces the viscosity ofthe viscous hydrocarbons in the reservoir, thereby enhancing themobility of the hydrocarbons and enabling them to flow downward throughthe formation under the force of gravity. The mobile hydrocarbons draininto the lower, horizontal well, referred to as the “production” well.The hydrocarbons are collected in the production well and are producedto the surface via natural flow or artificial lift (i.e., with orwithout artificial lift).

Another thermal technique for recovering viscous hydrocarbons is a “hot”waterflooding operation, also referred to as a hot water injectionoperation. In a conventional or “cold” waterflood, liquid water isinjected into the reservoir without increasing its temperature prior toinjection, and thus, is typically injected into the reservoir at atemperature that is less than or equal to the ambient temperature of thereservoir, whereas in a “hot” waterflood, the temperature of the liquidwater is increased prior to injection, and thus, is typically injectedinto the reservoir at a temperature that is greater than the ambienttemperature of the reservoir (e.g., the water is heated before beinginjected into the reservoir). The hot water provides the added benefitof adding thermal energy to the reservoir, which decreases the viscosityof the hydrocarbons, thereby allowing the hydrocarbons to move moreeasily toward production wells. Accordingly, hot waterfloods arecommonly used to recover viscous oils, whereas cold waterfloods arecommonly used with light and medium oils.

BRIEF SUMMARY OF THE DISCLOSURE

Embodiments of methods for producing hydrocarbons within a reservoir ina subterranean formation are disclosed herein. The reservoir having anambient temperature and an ambient pressure. In one embodiment, themethod comprises (a) injecting an aqueous solution into the reservoirwith the reservoir at the ambient temperature. The aqueous solutioncomprises water and a thermally activated chemical species. Thethermally activated chemical species is urea, a urea derivative, or acarbamate. The thermally activated chemical agent is thermally activatedat or above a threshold temperature less than 200° C. In addition, themethod comprises (b) thermally activating the thermally activatedchemical species in the aqueous solution during or after (a) at atemperature equal to or greater than the threshold temperature toproduce carbon-dioxide and at least one of ammonia, amine, andalkanolamine within the reservoir. Further, the method comprises (c)increasing the water wettability of the subterranean formation inresponse to the thermally activation in (b). Still further, the methodcomprises (d) waterflooding the reservoir with water after (a), (b) and(c).

Embodiments of methods method for recovering hydrocarbons fromhydrocarbon bearing rock are disclosed herein. In one embodiment, themethod comprises (a) applying an aqueous solution to the rock. Theaqueous solution comprises water and a thermally activated chemicalspecies. The thermally activated chemical species is urea, a ureaderivative, or a carbamate. The thermally activated chemical agent isthermally activated at or above a threshold temperature less than 200°C. In addition, the method comprises (b) thermally activating thethermally activated chemical species in the aqueous solution during orafter (a) at a temperature equal to or greater than the thresholdtemperature to produce carbon-dioxide and at least one of ammonia,amine, and alkanolamine within the rock. Further, the method comprises(c) increasing the water wettability of the rock in response to thethermally activation in (b). Still further, the method comprises (d)flushing the rock with water after (a), (b), and (c).

Embodiments described herein comprise a combination of features andadvantages intended to address various shortcomings associated withcertain prior devices, systems, and methods. The foregoing has outlinedrather broadly the features and technical advantages of the invention inorder that the detailed description of the invention that follows may bebetter understood. The various characteristics described above, as wellas other features, will be readily apparent to those skilled in the artupon reading the following detailed description, and by referring to theaccompanying drawings. It should be appreciated by those skilled in theart that the conception and the specific embodiments disclosed may bereadily utilized as a basis for modifying or designing other structuresfor carrying out the same purposes of the invention. It should also berealized by those skilled in the art that such equivalent constructionsdo not depart from the spirit and scope of the invention as set forth inthe appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of theinvention, reference will now be made to the accompanying drawings inwhich:

FIG. 1 is a schematic cross-sectional side view of an embodiment of asystem in accordance with the principles described herein for producinghydrocarbons from a subterranean formation;

FIG. 2 is a graphical illustration of an embodiment of a method inaccordance with the principles described herein for producing viscoushydrocarbons in the reservoir of FIG. 1 using the system of FIG. 1;

FIG. 3 is a schematic cross-sectional side view of the system of FIG. 1illustrating a loaded zone formed by injecting the aqueous solution intothe reservoir of FIG. 1 according to the method of FIG. 2;

FIG. 4 is a schematic cross-sectional side view of the system of FIG. 1illustrating a thermal chamber formed by injection of hot water or steaminto the reservoir of FIG. 1 to thermally activate the chemical agent(s)in the aqueous solution according to the method of FIG. 2;

FIG. 5 is a graphical illustration of an embodiment of a method inaccordance with the principles described herein for producing viscoushydrocarbons in the reservoir of FIG. 1 using the system of FIG. 1;

FIG. 6 is a graphical illustration of the amount of urea reacted versustemperature;

FIG. 7 is a graphical illustration of the percentage of originaloil-in-place (OIP) recovered from synthetic oil sand samples treatedwith different steam comprising different concentrations of ureaaccording to Example 2; and

FIG. 8 is an image of one of the synthetic oil sand samples from Example2 treated with steam comprising 5 wt % urea followed by the applicationof cold water.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments.However, one skilled in the art will understand that the examplesdisclosed herein have broad application, and that the discussion of anyembodiment is meant only to be exemplary of that embodiment, and notintended to suggest that the scope of the disclosure, including theclaims, is limited to that embodiment.

Certain terms are used throughout the following description and claimsto refer to particular features or components. As one skilled in the artwill appreciate, different persons may refer to the same feature orcomponent by different names. This document does not intend todistinguish between components or features that differ in name but notfunction. The drawing figures are not necessarily to scale. Certainfeatures and components herein may be shown exaggerated in scale or insomewhat schematic form and some details of conventional elements maynot be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to . . . .” Also, theterm “couple” or “couples” is intended to mean either an indirect ordirect connection. Thus, if a first device couples to a second device,that connection may be through a direct connection, or through anindirect connection via other devices, components, and connections. Inaddition, as used herein, the terms “axial” and “axially” generally meanalong or parallel to a central axis (e.g., central axis of a body or aport), while the terms “radial” and “radially” generally meanperpendicular to the central axis. For instance, an axial distancerefers to a distance measured along or parallel to the central axis, anda radial distance means a distance measured perpendicular to the centralaxis. Any reference to up or down in the description and the claims willbe made for purposes of clarity, with “up”, “upper”, “upwardly” or“upstream” meaning toward the surface of the borehole and with “down”,“lower”, “downwardly” or “downstream” meaning toward the terminal end ofthe borehole, regardless of the borehole orientation.

As existing reserves of hydrocarbons (e.g., light crude oil) aredepleted and the demand for hydrocarbon products continue to rise, thereis a push to develop techniques for maximizing the quantity of theoriginal OIP that is recovered and produced. Waterflooding operationsprovide one secondary recovery technique for enhancing the percentage ofthe original OIP that is recovered, up to an additional 30% of theoriginal OIP. In addition, thermal recovery techniques such as SAGD andhot waterflooding provide techniques to enhance recovery of viscous oilssuch as heavy oil and bitumen. However, such operations alone may resultin less than desirable production yields. For example, after coldwaterflooding operations, as much as 50% of the original OIP may remainin the reservoir; and after thermally based operations suitable forviscous oil recovery, such as SAGD and hot waterflooding, as much as 40%of the original OIP may remain in the reservoir. However, as will bedescribed in more detail below, embodiments of systems and methodsdescribed herein offer the potential to enhance the quantity of theoriginal OIP recovered from the reservoir.

Referring now to FIG. 1, an embodiment of a system 10 for producinghydrocarbons including light oil, medium oil, and viscous oil (e.g.,bitumen and heavy oil) from a subterranean formation 100 by loading thereservoir 105 with one or more chemical agent(s), thermally activatingthe chemical agent(s) in the reservoir 105, and then performing awaterflooding operation is shown. Moving downward from the surface 5,formation 100 includes an upper overburden layer or region 101 ofconsolidated cap rock, an intermediate layer or region 102 of rock, anda lower underburden layer or region 103 of consolidated rock. Layers101, 103 are formed of generally impermeable formation material (e.g.,limestone). However, layer 102 is formed of a generally porous,permeable formation material (e.g., sandstone), thereby enabling thestorage of hydrocarbons therein and allowing the flow and percolation offluids therethrough. In particular, layer 102 contains a reservoir 105of hydrocarbons (reservoir 105 shaded in FIG. 1).

System 10 includes an injection well 120 and a production well 130. Eachwell 120, 130 extends from an uphole end 120 a, 130 a, respectively,disposed at the surface 5 through overburden layer 101 and the reservoir105 to a downhole end 120 b, 130 b, respectively, proximal underburdenlayer 103. In this embodiment, wells 120, 130 are horizontally-spacedand vertically oriented. The portions of each well 120, 130 extendingthrough layer 102 and reservoir 105 are lined with perforated or slottedliners, and thus, are open to reservoir 105. Although FIG. 1 onlyillustrates one injection well 120 and one production well 130, system10 can include a plurality of injection wells 120 and/or a plurality ofproduction wells 130. Further, although the waterflooding wells 120, 130are vertically oriented in this embodiment, in other embodiments, thewaterflooding wells (e.g., wells 120, 130) can be horizontally-spacedand include horizontal sections.

Referring now to FIG. 2, an embodiment of a method 200 for producinghydrocarbons from reservoir 105 (or portion of reservoir 105) usingsystem 10 is shown. In this embodiment, and as will described in moredetail below, reservoir 105 is loaded with an aqueous solution includingone or more chemical agent(s) prior to initiating production operations.The chemical agent(s) are thermally activated within the reservoir 105to increase the water wettability of the formation 100, which offer thepotential to increase the production of hydrocarbons from well 130 in asubsequent waterflooding operation. Since the chemical agent(s) areinjected in an aqueous solution, method 200 is particularly suited foruse with reservoirs exhibiting a native permeability to water and isgenerally independent of the native wettability of the reservoir.

Although embodiments of method 200 can be used to produce hydrocarbonshaving any viscosity under ambient reservoir conditions (ambientreservoir temperature and pressure) including, without limitation, lighthydrocarbons, heavy hydrocarbons, bitumen, etc., embodiments of method200 may provide particular advantages for producing oils having an APIgravity less than 30°. In general, viscous hydrocarbons having aviscosity greater than 10,000 cP under ambient reservoir conditions areimmobile within the reservoir and typically cannot be producedeconomically using conventional in-situ recovery methods.

Beginning in block 201 of method 200, one or more chemical agents forinjection into reservoir 105 are selected. The purpose of the chemicalagent(s) is to increase the water wettability of the formation rock inreservoir 105 in response to thermal energy. Thus, selection of theparticular chemical agent(s) is based, at least in part, on its abilityto increase the water wettability of the formation 100 upon thermalactivation. Without being limited by this or any particular theory, theability of a chemical agent to increase the wettability of a reservoir(e.g., reservoir 105) is believed to depend on a variety of factorsincluding, without limitation, the degree to which the chemical agent orproducts thereof can alter the pH of the connate water in the reservoirto a value near the isoelectric point such that polar componentsadsorbed on rock surfaces can be desorbed more easily, the reactivity ofthe chemical agent or products thereof with the organic bases or acidson the rock surfaces, whether the chemical agent or products thereof canfacilitate the formation of gas bubbles on rock surfaces to facilitatedesorption of adsorbed hydrocarbons from the rock surfaces, whetherreactivity of the chemical agent or products thereof yield compoundscapable of reacting with functional groups on the rock surfaces, etc.Core and/or oil samples from the formation of interest can be testedwith various chemical agents to facilitate the selection in block 201.In this embodiment, each selected chemical agent is water soluble suchthat it can be injected into reservoir 105 in an aqueous solution aswill be described in more detail below. In embodiments described herein,each selected chemical agent preferably exhibits a solubility of atleast 0.01 g/ml in aqueous solution at 25° C. and 1 atm pressure, andmore preferably at least 0.05 g/ml in aqueous solution at 25° C. and 1atm pressure. The cost and availability of various chemical agent(s) mayalso impact the selection in block 201.

Although a variety of chemical compounds may be useful as chemicalagents, in embodiments described herein, the one or more chemicalagent(s) selected in block 201 are water soluble thermally activatedchemical species that can be used alone, with one or more other chemicalagents or compounds, or combinations thereof. In addition, eachthermally activated chemical species selected in block 201 is a chemicalspecies that is non-reactive or substantially non-reactive in reservoir105, as well as at the surface, below a threshold temperature, butdecomposes, dissociates, or reacts at a temperature greater than orequal to the threshold temperature to yield or release one or morecompounds that increase the water wettability of the reservoir rock suchas: (a) a gas or gases that enhances the water wettability of thereservoir rock (e.g., carbon-dioxide gas, ammonia gas, etc.); (b) analkaline or acidic compound or compounds, which can react with naturallyoccurring acids or bases, respectively, in the hydrocarbon reservoir tochange the surface charge of the reservoir rock to reduce adsorption ofpolar compounds (e.g., hydrocarbons, natural or injected surfactants,etc.) and increase the water wettability of the reservoir rock; (c) analkaline or acidic compound or compounds that can change the electriccharge of the formation rock surfaces to increase the water wettabilityof the reservoir rock; (d) a surfactant or surfactant-like compound; or(e) combinations thereof. Accordingly, the threshold temperature mayalso be referred to herein as the “activation” or “trigger” temperature.Further, as used herein, the phrases “substantially non-decomposable”and “substantially non-reactive” refer to a chemical species that has aconversion rate (via decomposition, reaction, hydrolysis, dissociation,or combinations thereof) of less than 1 mol % over a 24 hour period inan aqueous solution at ambient reservoir temperatures as preparedaccording to block 202 described in more detail below, and in thepresence of hydrocarbons in a reservoir below the threshold temperature.It should be appreciated that the decomposition, dissociation, orreaction of the thermally activated chemical species at or above thethreshold temperature may be directly or indirectly thermally driven.

In embodiments described herein, each thermally activated chemicalspecies selected as a chemical agent in block 201 is urea, a ureaderivative, or a carbamate (e.g., ammonium carbamate, amine carbamate,and alkanolamine carbamate). In embodiments described herein, “ureaderivatives” include, without limitation, 1-methyl urea, 1-ethyl urea,1,1-dimethyl urea, 1,3-dimethyl urea, 1,1-diethyl urea, andbi(hydroymethyl) urea. As is known in the art, carbamates are chemicalcompounds with the formula R₁R₂NC(O)₂R₃, where R₁, R₂, R₃ are eachindependently selected from an alkyl group, alkanol group, phenyl group,benzyl group, hydroxyl, or hydrogen. Carbamates are formed (a) byinjecting carbon-dioxide into an aqueous solution of ammonium, amine, oralkanolamine, or (b) by reacting alcohols with urea. The carbamateresulting from the injection of carbon-dioxide into aqueous ammonium iscommonly referred to as “ammonium carbamate;” the carbamate resultingfrom the injection of carbon-dioxide into aqueous amine is commonlyreferred to as “amine carbamate;” and the carbamate resulting from theinjection of carbon-dioxide into aqueous alkanolamine is commonlyreferred to as “alkanolamine carbamate.” For suitable water solubility,in embodiments described herein, any R₁, R₂, R₃ that is any alkyl groupor alkanol group is preferably a C1-C2 alkyl group or a C1-C2 alkanolgroup, respectively.

Urea and urea derivatives are water soluble and generally non-reactivebelow 80° C., but undergo a hydrolysis reaction in the presence of waterat a threshold temperature of about 80° C. to produce carbon-dioxide andammonia. The carbon-dioxide and ammonia each exist in equilibriumbetween gaseous and liquid phases—gaseous carbon-dioxide and liquidcarbon-dioxide (the carbon-dioxide equilibrium is shifted more towardsthe gaseous phase), and gaseous ammonia and liquid ammonia. Selectcarbamates are also water soluble and generally non-reactive below20-50° C. (may vary for different carbamates), but undergo a hydrolysisreaction in the presence of water at a threshold temperature of about20-50° C. to produce carbon-dioxide and at least one of ammonia, amine,and alkanolamine depending on the compounds used to synthesize thecarbamate. For example, the hydrolysis of ammonium carbamate in thepresence of water yields carbon-dioxide and ammonia, the hydrolysis ofaqueous amine carbamate in the presence of water yields carbon-dioxideand amine, and the hydrolysis of alkanolamine carbamate in the presenceof water yields carbon-dioxide and alkanolamine. In each case, thecarbon-dioxide and the ammonia, amine, or alkanolamine (depending on thecarbamate) each exist in equilibrium between gaseous and liquidphases—gaseous carbon-dioxide and liquid carbon-dioxide (thecarbon-dioxide equilibrium is shifted more towards the gaseous phase),gaseous ammonia and liquid ammonia in aqueous solution (for hydrolysisof ammonium carbamate), gaseous amine and liquid amine in aqueoussolution (for hydrolysis of amine carbamate), and gaseous alkanolamineand liquid alkanolamine in aqueous solution (for hydrolysis ofalkanolamine carbamate). As will be described in more detail below, thecarbon-dioxide, ammonia, amine, and alkanolamine resulting from thehydrolysis reactions described above increase the water wettability ofthe formation rock in reservoir 105.

Moving now to block 202, the selected chemical agent(s) is/are mixedwith a brine (i.e., solution of salt in water) to form an aqueoussolution. The brine preferably has a composition (e.g., saltconcentration and composition) that does not damage the formation rockin reservoir 105. In general, this can be determined by performinginjectivity tests with core samples recovered from reservoir 105 usingmethods known in the art. The concentration of each chemical agent inthe aqueous solution can be varied depending on a variety of factors,but is preferably at least about 0.01 wt % and less than or equal to thesolubility limit of the chemical agent in the brine under ambientreservoir conditions (i.e., at the ambient temperature and pressure ofreservoir 105). In embodiments described herein, the concentration ofeach chemical agent (e.g., urea) in the aqueous solution is preferablybetween 1.0 and 20.0 wt %.

Referring still to FIG. 2, in block 203, the parameters for loading orinjecting the reservoir 105 with the aqueous solution comprising thechemical agent(s) are determined. In general, the injection parameterscan be determined by any suitable means known in the art such as byperforming injectivity tests. The injection parameters include, withoutlimitation, the pressure, the temperature, and the flow rate at whichthe aqueous solution will be injected into reservoir 105. The injectionpressure of the aqueous solution is preferably sufficiently high enoughto enable injection into reservoir 105 (i.e., the pressure is greaterthan to the ambient pressure of reservoir 105), and less than thefracture pressure of overburden 101. In general, injection pressure ofthe aqueous solution can be above, below, or equal to the fracturepressure of reservoir 105. For producing viscous oil having an APIgravity less than 30°, the injection pressure is preferably less thanthe displacement pressure of the viscous oil to facilitate the deliveryof the chemical agent(s) to the formation water. The injectiontemperature of the aqueous solution is preferably greater than thefreezing point of the aqueous solution and less than 40° C., and morepreferably greater than the freezing point of the aqueous solution andless than the threshold temperature. It should be appreciated that theambient temperature at the surface 5 may be greater than the ambienttemperature of reservoir 105, and thus, the aqueous solution stored thesurface 5 may have a temperature greater than the ambient temperature ofreservoir 105 (i.e., the injection temperature of the aqueous solutionstored at the surface 5 may be greater than the ambient temperature ofreservoir 105). However, as noted above, even in such cases, theinjection temperature of the aqueous solution is preferably greater thanthe freezing point of the aqueous solution and less than 40° C.

Moving now to block 204, reservoir 105 is loaded or injected with theaqueous solution according to the injection parameters determined inblock 203. Since the aqueous solution is injected into reservoir 105with reservoir 105 at its ambient temperature, injection of the aqueoussolution according to block 204 may be referred to herein as “cold”loading of reservoir 105. During the cold loading of reservoir 105 inblock 204, the aqueous solution can be injected into reservoir 105utilizing one of wells 120, 130, both wells 120, 130, or combinationsthereof over time. The aqueous solution is preferably injected intoreservoir 105 via injection well 120 alone, via both wells 120, 130 atthe same time, or via both wells 120, 130 at the same time followed byinjection via well 120 alone. It should be appreciated that since theaqueous solution is injected into the reservoir 105 in block 204 beforethe waterflood and associated production in blocks 206, 207,respectively, the aqueous solution can be injected into the reservoir inblock 204 through one of the wells 120, 130 while the other well 120,130 is being formed (e.g., drilled). Then, after formation of the secondof the wells 120, 130, the aqueous solution can be injected solelythrough the first of the wells 120, 130, solely through the second ofthe wells 120, 130, or simultaneously through both wells 120, 130. Ingeneral, the aqueous solution can be injected into the reservoir 105continuously, intermittently, or pulsed by controllably varying theinjection pressure within an acceptable range of pressures as determinedin block 203. Pulsing the injection pressure of the aqueous solutionoffers the potential to enhance distribution of the aqueous solution inreservoir 105 and facilitate dilation of reservoir 105. It should beappreciated that any one or more of these injection options can beperformed alone or in combination with other injection options.

In implementations where production well 130 is not employed forinjection of the aqueous solution, production well 130 is preferablymaintained at a pressure lower than the ambient pressure of reservoir105 (e.g., with a pump) to create a pressure differential and associateddriving force for the migration of fluids (e.g., connate water and/orthe injected aqueous solution) into production well 130. Pumping fluidsout of production well 130 to maintain the lower pressure also enableschemical analysis and monitoring of the fluids flowing into productionwell 130 from the surrounding formation 101, which can provide insightas to the migration of the aqueous solution through reservoir 105 andthe saturation of reservoir 105 with the aqueous solution.

In general, the volume of aqueous solution and duration of injection inblock 204 will depend on a variety of factors including, withoutlimitation, the volume of reservoir 105 to be loaded (i.e., the entirereservoir 105 vs. a portion of reservoir 105), the permeability towater, the water saturation, and the maximum injection pressure.

Referring briefly to FIG. 3, reservoir 105 and formation 100 are shownfollowing injection of the aqueous solution according to block 204. InFIG. 3, the aqueous solution is represented with reference numeral“110.” The injected aqueous solution 110 forms a loaded zone 111extending radially outward and longitudinally along the well(s) 120, 130from which the solution 110 was injected into reservoir 105.

As previously described, the selected chemical agents are thermallyactivated chemical species that are (1) non-decomposable orsubstantially non-decomposable and (2) non-reactive or substantiallynon-reactive in reservoir 105 below the threshold temperature. Thus, ifthe ambient reservoir temperature is below the threshold temperature,the chemical agent(s) in the aqueous solution do not substantiallydecompose or react with or otherwise alter the water wettability inreservoir 105 upon injection.

Referring again to FIG. 2, in block 205, after loading the reservoir 105in block 204, the thermally activated chemical species in the aqueoussolution are thermally “activated” or “triggered.” In general, thethermally activated chemical species can be thermally activated ortriggered by (a) the thermal energy of the reservoir 105 itself if theambient temperature of the reservoir 105 is at or above the thresholdtemperature; or (b) thermal energy added to the reservoir 105 if theambient temperature of the reservoir 105 is below the thresholdtemperature. Thus, if the ambient temperature of the reservoir 105 is ator above the threshold temperature of the thermally activated chemicalspecies, then the chemical species in the aqueous solution will begindecompose, dissociate, or react upon injection into the reservoir 105 atthe ambient temperature of the reservoir 105 to yield or release one ormore compounds that increase the water wettability of the reservoir rockas described above. However, if the ambient temperature of the reservoir105 is not at or above the threshold temperature of the thermallyactivated chemical species, then thermal energy is added to thereservoir 105 in block 205 to increase the temperature of the reservoir105 to a temperature equal to or greater than the threshold temperatureof the thermally activated chemical species, thereby enabling thethermally activated chemical species in the aqueous solution todecompose, dissociate, or react (at an elevated temperature greater thanthe ambient temperature of the reservoir 105) to yield or release one ormore compounds that increase the water wettability of the reservoir rockas described above.

In general, any suitable means for adding thermal energy to thereservoir 105 can be employed to raise the temperature of the reservoir105 to or above the threshold temperature of the thermally activatedchemical species if the temperature of the reservoir 105 is below thethreshold temperature. However, in embodiments described herein, thermalenergy is preferably added to the reservoir 105 in block 205 byinjecting steam into the reservoir 105 (e.g., a SAGD operation) and/orinjecting hot liquid water into the reservoir 105 (e.g., a hotwaterflooding operation).

Referring briefly to FIG. 4, for both hot waterflooding and steaminjection to increase the temperature of the reservoir 105 in block 205,the hot water or steam, respectively, is injected into reservoir 105 viainjection well 120. Once injected into reservoir 105, the hot water orsteam percolates through the reservoir 105 radially outward andlongitudinally along injection well 120, thereby forming a thermalchamber 140. The thermal energy from chamber 140 raises the temperatureof reservoir 105 and loaded zone 111 to an elevated temperature that is(i) greater than the ambient temperature of reservoir 105, and (ii)equal to or greater than the threshold temperature of the thermallyactivated chemical species in the aqueous solution. Once the temperatureof the reservoir 105 is at or above the threshold temperature, thethermally activated chemical species in the aqueous solution decompose,dissociate, or react to yield or release the one or more compounds thatincrease the water wettability of the reservoir rock as described above.It should also be appreciated that the thermal energy from chamber 140and associated elevated temperature reduces the viscosity of the viscoushydrocarbons in reservoir 105.

As previously described, in this embodiment, the thermally activatedchemical species selected in block 201 is (1) urea or a urea derivative,which undergo hydrolysis in aqueous solution upon thermal activation(i.e., at or above 80° C.) to produce carbon-dioxide and ammonia; (2) acarbamate (e.g., ammonium carbamate, amine carbamate, and alkanolaminecarbamate), which undergo hydrolysis in aqueous solution upon thermalactivation (i.e., at or above 20-50° C.) to produce carbon-dioxide andat least one of ammonia, amine, and alkanolamine; or combinationsthereof. The carbon-dioxide gas increases the water wettability of theformation rock in reservoir 105. In addition, the carbon-dioxide gasincreases the pressure in the reservoir 105, which offers the potentialto enhance mobilization of the hydrocarbons in reservoir 105. Theammonia, amine, and alkanolamine also increases the water wettability ofthe formation rock in reservoir 105. In addition, the ammonia, amine,and alkanolamine react with organic acid in the hydrocarbons to formsurfactants in-situ, which offer the potential to emulsify thehydrocarbons, particularly viscous oil, to form oil-in-water emulsions,thereby reducing the oil viscosity and further increasing themobilization of the hydrocarbons.

Referring again to FIG. 2, a soaking period can optionally be employedafter thermally activating the chemical agent(s) in block 205 and beforewaterflooding in block 206 to provide ample time for thereaction/decomposition products of the chemical agent(s) to interactwith the formation rock and hydrocarbons in the reservoir 105. Inembodiments where a soaking period is employed, the soaking period ispreferably between 1 and 30 days. In other embodiments, no soakingperiod is employed, and method 100 proceeds immediately from block 205to block 206.

Referring still to FIG. 2, after thermally activating the thermallyactivated chemical species (e.g., urea), a waterflooding operation isperformed in block 206. In general, the waterflooding operation in block206 can be a cold or hot waterflooding operation. In the waterfloodingoperation according to block 206, water is injected under pressure intothe reservoir 105 through injection well 120. The water increases thepressure in reservoir 105, and as the water moves through the reservoir105, it displaces hydrocarbons from the pore spaces. The hydrocarbondisplacement is enhanced in embodiments described herein by the increasein the water wettability of the reservoir 105 resulting from the thermalactivation of the thermally activated chemical species. In particular,waterflooding of the treated reservoir 105 in block 206 after treatmentof the reservoir 105 in block 205 leads to “beading” and “rolling up” ofthe hydrocarbons in reservoir 105 that are attached to rock/formationsurfaces. The resulting hydrocarbon droplets are more easily pushed orswept by the water through the reservoir 105 and into production well130. The hydrocarbons and any water collected in production well 130 areproduced to the surface via natural flow or artificial lift (i.e., withor without artificial lift) according to block 207.

In general, the waterflood operation in block 206 can be performed usingany suitable type of water. In embodiments described herein, the waterused for the waterflood operation (e.g., in block 206) preferably has acomposition (e.g., salt concentration and composition) that does notdamage the formation rock in reservoir 105. In general, this can bedetermined by performing injectivity tests with core samples recoveredfrom reservoir 105 using methods known in the art. In addition, inembodiments described herein, the water used in the waterfloodingoperation preferably has its salinity (i.e., dissolved solids and ioniccontent) tailored and adjusted as described, for example, in U.S. Pat.Nos. 7,987,907 and 8,439,111, each of which is incorporated herein byreference in its entirety. In some embodiments, the water injected toperform the waterflood in block 206 has a total dissolved solids (TDS)greater than 200 ppm and less than 5,000 ppm. In other embodiments, thewater used in the waterflooding operation (e.g., in block 206) comprisesa brine with a relatively low multivalent cation content and a totaldissolved solids (TDS) less than or equal to 50,000 ppm. For example, insome such embodiments, the multivalent cation content is less than 300ppm, alternatively less than 100, or alternatively less than 50 ppm. Itshould be appreciated that the water used for the waterflooding canoptionally include polymer(s), polymer pre-cursor(s), delayed actionpolymer(s), or combinations thereof. Further, the waterflood operationin block 206 can optionally be performed by cyclically injecting waterfollowed by gas such as part of a Water Alternated with Gas (WAG)operation.

Referring now to FIG. 5, an embodiment of another method 300 forproducing hydrocarbons from reservoir 105 (or portion of reservoir 105)using system 10 is shown. Method 300 is substantially the same as method200 previously described with the exception that in this embodiment,reservoir 105 is loaded with an aqueous solution including one or morechemical agent(s) and nanoparticles prior to initiating productionoperations. The chemical agent(s) are thermally activated within thereservoir 105. The products resulting from the thermal activation of thechemical agents in combination with the nanoparticles increase the waterwettability of the formation rock in reservoir 105, form foams in-situ,reduce the viscosity of the hydrocarbons through the formation ofoil-in-water emulsions, and increase pressure within the formation,thereby accelerating mobilization and production of hydrocarbons fromwell 30 in a subsequent waterflooding operation. Since the chemicalagent(s) are injected in an aqueous solution, method 300 is particularlysuited for use with reservoirs exhibiting a native permeability to waterand is generally independent of the native wettability of the reservoir.

Although embodiments of method 300 can be used to produce hydrocarbonshaving any viscosity under ambient reservoir conditions (ambientreservoir temperature and pressure) including, without limitation, lightoil, medium oil, and viscous oil (e.g., heavy oil and bitumen),embodiments of method 300 are particularly suited to producinghydrocarbons having an API gravity less than 30° under ambient reservoirconditions. In general, viscous hydrocarbons having a viscosity greaterthan 10,000 cP under ambient reservoir conditions are immobile withinthe reservoir and typically cannot be produced economically usingconventional in-situ recovery methods.

Beginning in block 301 of method 300, one or more chemical agents forinjection into reservoir 105 are selected. Block 301 is the same asblock 201 of method 200 previously described. In particular, the purposeof the chemical agent(s) is to increase the water wettability of theformation rock in reservoir 105 in response to thermal energy. Thus,selection of the particular chemical agent(s) is based, at least inpart, on its ability to increase the water wettability of the formationof interest upon thermal activation. As previously described, withoutbeing limited by this or any particular theory, the ability of achemical agent to increase the wettability of a reservoir is believed todepend on a variety of factors including, without limitation, the degreeto which the chemical agent or products thereof can alter the pH of theconnate water in the reservoir to a value near the isoelectric pointsuch that polar components adsorbed on rock surfaces can be desorbedmore easily, the reactivity of the chemical agent or products thereofwith the organic bases or acids on the rock surfaces, whether thechemical agent or products thereof can facilitate the formation of gasbubbles on rock surfaces to facilitate desorption of adsorbedhydrocarbons from the rock surfaces, whether reactivity of the chemicalagent or products thereof yield compounds capable of reacting withfunctional groups on the rock surfaces, etc. Core and/or oil samplesfrom the formation of interest can be tested with various chemicalagents to facilitate the selection in block 301. In this embodiment,each selected chemical agent is water soluble such that it can beinjected into reservoir 105 in an aqueous solution as will be describedin more detail below. In embodiments described herein, each selectedchemical agent preferably exhibits a solubility of at least 0.01 g/ml inaqueous solution at 25° C. and 1 atm pressure, and more preferably atleast 0.05 g/ml in aqueous solution at 25° C. and 1 atm pressure. Thecost and availability of various chemical agent(s) may also impact theselection in block 301.

Although a variety of chemical compounds may be useful as chemicalagents, in embodiments described herein, the one or more chemicalagent(s) selected in block 301 are water soluble thermally activatedchemical species that can be used alone, with one or more other chemicalagents or compounds, or combinations thereof. In addition, eachthermally activated chemical species selected for use as a chemicalagent in block 301 is a chemical species that is non-reactive orsubstantially non-reactive in reservoir 105, as well as at the surface,below a threshold temperature, but decomposes, dissociates, or reacts ata temperature greater than or equal to the threshold temperature toyield or release one or more compounds that increase the waterwettability of the reservoir rock such as: (a) a gas or gases thatenhances the water wettability of the reservoir rock (e.g.,carbon-dioxide gas, ammonia gas, etc.); (b) an alkaline or acidiccompound or compounds, which can react with naturally occurring acids orbases, respectively, in the hydrocarbon reservoir to change the surfacecharge of the reservoir rock to reduce adsorption of polar compounds(e.g., hydrocarbons, natural or injected surfactants, etc.) and increasethe water wettability of the reservoir rock; (c) an alkaline or acidiccompound or compounds that can change the charge of the formation rocksurfaces to increase the water wettability of the reservoir rock; (d) asurfactant or surfactant-like compound; or (e) combinations thereof.Accordingly, the threshold temperature may also be referred to herein asthe “activation” or “trigger” temperature. Further, as used herein, thephrases “substantially non-decomposable” and “substantiallynon-reactive” refer to a chemical species that has a conversion rate(via decomposition, reaction, hydrolysis, dissociation, or combinationsthereof) of less than 1 mol % over a 24 hour period in an aqueoussolution at ambient reservoir temperatures as prepared according toblock 202 described in more detail below, and in the presence ofhydrocarbons in a reservoir below the threshold temperature. It shouldbe appreciated that the decomposition, dissociation, or reaction of thethermally activated chemical species at or above the thresholdtemperature may be directly or indirectly thermally driven.

In embodiments described herein, each thermally activated chemicalspecies selected in block 301 is urea, a urea derivative, is urea, aurea derivative, or a carbamate (e.g., ammonium carbamate, aminecarbamate, and alkanolamine carbamate). As previously described, ureaand urea derivatives are water soluble and generally non-reactive below80° C., but undergo a hydrolysis reaction in the presence of water at athreshold temperature of about 80° C. to produce carbon-dioxide andammonia, each of which exist in equilibrium between gaseous and liquidphases. In addition, as previously described, select carbamates are alsowater soluble and generally non-reactive below 20-50° C., but undergo ahydrolysis reaction in the presence of water at a threshold temperatureof about 20-50° C. to produce carbon-dioxide and at least one ofammonia, amine, and alkanolamine depending on the compounds used tosynthesize the carbamate. The carbon-dioxide and the ammonia, amine, oralkanolamine (depending on the carbamate) each exist in equilibriumbetween gaseous and liquid phases. The carbon-dioxide, ammonia, amine,and alkanolamine resulting from the hydrolysis reactions described aboveincrease the water wettability of the formation rock in reservoir 105.

Moving now to block 302, the selected chemical agent(s) is/are mixedwith a brine (i.e., solution of salt in water) to form an aqueoussolution. The brine preferably has a composition (e.g., saltconcentration and composition) that does not damage the formation rockin reservoir 105. In general, this can be determined by performinginjectivity tests with core samples recovered from reservoir 105 usingmethods known in the art. The concentration of each chemical agent inthe aqueous solution can be varied depending on a variety of factors,but is preferably at least about 0.01 wt % and less than or equal to thesolubility limit of the chemical agent in the brine under ambientreservoir conditions (i.e., at the ambient temperature and pressure ofreservoir 105). In embodiments described herein, the concentration ofeach chemical agent (e.g., urea) in the aqueous solution is preferablybetween 1.0 and 20.0 wt %.

Unlike method 200 previously described, in this embodiment, a pluralityof nanoparticles are added to the aqueous solution containing theselected chemical agent(s) in block 302. Each of the nanoparticlespreferably has a size or diameter between 1.0 nanometer and 1.0 micron,and more preferably between 1.0 nanometers and 100.0 nanometers. Inaddition, the concentration of the nanoparticles in the aqueous solutionis preferably between 10 and 10,000 ppmw. In this embodiment, thenanoparticles added to the aqueous solution in block 302 are preferablymade of inorganic or polymeric materials. In general, any suitable typeof inorganic or polymeric nanoparticles can be used. Examples ofsuitable inorganic nanoparticles include, without limitation, metaloxide nanoparticles (e.g., silica, zinc oxide, and the like), carbonatenanoparticles (e.g., calcium carbonate and the like), carbonnanoparticles, titanium oxide nanoparticles, alumina nanoparticles,carbon nanotubes, and nanoparticles comprising functionalized carbonmaterials (e.g. graphite, graphene, etc.). Examples of polymericnanoparticles include, without limitation, polystyrene nanoparticles.

In embodiments described herein, each nanoparticle preferably has anouter surface that is partially water-wet and partially oil-wet, andpreferably slightly more water-wet than oil-wet. Coatings can be used toachieve the desired degree of water-wettability and oil-wettability ofthe outer surface (e.g., an outer surface that is 75% water-wet and 25%oil-wet). For example, if the material a given nanoparticle is made ofis oil-wet, that nanoparticle can be partially coated with a materialthat is water-wet such that the outer surface of the nanoparticle ispartially oil-wet (i.e., the exposed portion of the nanoparticle isoil-wet) and partially water-wet (i.e., the coated portion of thenanoparticle is water-wet). As noted above the outer surface of eachnanoparticle is preferably mixed-wet (i.e., partially water-wet andpartially oil-wet), but preferably more water-wet than oil-wet. Thus,for nanoparticles made of oil-wet materials, at least 50% of the totalouter surface area of each nanoparticle, and more preferably 50-75% ofthe total outer surface area of each nanoparticle comprises or is coatedwith a water-wet material (e.g., hydrophilic coating); and fornanoparticles made of water-wet materials, less than 50% of the totalouter surface area of each nanoparticle, and more preferably 25-50% ofthe total outer surface area of each such nanoparticle comprises or iscoated with an oil-wet material (e.g., hydrophobic coating). In general,any suitable water-wet or oil-wet coating can be applied to thenanoparticles. One exemplary coating material is silanes with differentfunctional groups that can react with silica to form hydrophobiccoatings. In general, the silica-silane ratio can be controlled toadjust the degree of hydrophobicity of the treated silica. Otherpossible coating materials include, but are not limited to, long chainamine(s), titanate(s), etc. As will be described in more detail below,nanoparticles having mixed-wet outer surfaces aid in stabilizinggas-in-water foams and oil-in-water emulsions formed in-situ in block305.

One or more surfactant(s) can optionally be added to the aqueoussolution in block 302. The concentration of the surfactant(s) in theaqueous solution is preferably between 10 and 10,000 ppmw. In general,any suitable surfactant(s) can be used. Examples of suitable surfactantsinclude, without limitation to, alkyl sulfonate, alkyl ether sulfate,Triton™ series non-ionic surfactants, and the like. As will be describedin more detail below, the surfactant(s) aid in stabilizing gas-in-waterfoams and oil-in-water emulsions formed in-situ in block 305, as well asreduce the potential for nanoparticles to be retained on the surfaces offormation rock.

Referring still to FIG. 5, in block 303, the parameters for loading orinjecting the reservoir 105 with the aqueous solution are determined.The injection parameters are determined in block 303 in the same manneras previously described with respect to block 203 of method 200. Theinjection pressure of the aqueous solution is preferably sufficientlyhigh enough to enable injection into reservoir 105 (i.e., the pressureis greater than to the ambient pressure of reservoir 105), and less thanthe fracture pressure of overburden 101. In general, injection pressureof the aqueous solution can be above, below, or equal to the fracturepressure of reservoir 105. For producing viscous oil (e.g., for use inconnection with reservoirs containing viscous oil), the injectionpressure is preferably less than the displacement pressure of theviscous oil. The injection temperature of the aqueous solution ispreferably greater than the freezing point of the aqueous solution andless than 40° C., and more preferably greater than the freezing point ofthe aqueous solution and less than the threshold temperature. It shouldbe appreciated that the ambient temperature at the surface 5 may begreater than the ambient temperature of reservoir 105, and thus, theaqueous solution stored the surface 5 may have a temperature greaterthan the ambient temperature of reservoir 105 (i.e., the injectiontemperature of the aqueous solution stored at the surface 5 may begreater than the ambient temperature of reservoir 105). However, asnoted above, even in such cases, the injection temperature of theaqueous solution is preferably greater than the freezing point of theaqueous solution and less than 40° C.

Moving now to block 304, reservoir 105 is loaded or injected with theaqueous solution according to the injection parameters determined inblock 303. Since the aqueous solution is injected into reservoir 105with reservoir 105 at its ambient temperature, injection of the aqueoussolution according to block 304 may be referred to herein as “cold”loading of reservoir 105. During the cold loading of reservoir 105 inblock 304, the aqueous solution can be injected into reservoir 105utilizing one well 120, 130, both wells 120, 130, or combinationsthereof over time. The aqueous solution is preferably injected intoreservoir 105 via injection well 120 alone, via both wells 120, 130 atthe same time, or via both wells 120, 130 at the same time followed byinjection well 120 alone. It should be appreciated that since theaqueous solution is injected into the reservoir 105 in block 304 beforethe waterflood and associated production in blocks 306, 307,respectively, the aqueous solution can be injected into the reservoir inblock 304 through one of the wells 120, 130 while the other well 120,130 is being formed (e.g., drilled). Following the formation of thesecond well 120, 130, the aqueous solution can be injected solelythrough the first well 120, 130, solely through the second well 120,130, or simultaneously through both wells 120, 130. In general, theaqueous solution can be injected into the reservoir 105 continuously,intermittently, or pulsed by controllably varying the injection pressurewithin an acceptable range of pressures as determined in block 303.Pulsing the injection pressure of the aqueous solution offers thepotential to enhance distribution of the aqueous solution in reservoir105 and facilitate dilation of reservoir 105. It should be appreciatedthat any one or more of these injection options can be performed aloneor in combination with other injection options.

In implementations where production well 130 is not employed forinjection of the aqueous solution, production well 130 is preferablymaintained at a pressure lower than the ambient pressure of reservoir105 (e.g., with a pump) to create a pressure differential and associateddriving force for the migration of fluids (e.g., connate water and/orthe injected aqueous solution) into production well 130. Pumping fluidsout of production well 130 to maintain the lower pressure also enableschemical analysis and monitoring of the fluids flowing into productionwell 130 from the surrounding formation 101, which can provide insightas to the migration of the aqueous solution through reservoir 105 andthe saturation of reservoir 105 with the aqueous solution.

Injection of the aqueous solution in block 304 is performed untilreservoir 105 (or portion of reservoir 105 to be loaded) is sufficientlycharged. Ideally, the aqueous solution is injected into reservoir 105until the total pore volume in reservoir 105 (or portion of reservoir105 to be loaded) available for water is filled with the aqueoussolution. However, practically, this may be extremely difficult, costly,and/or time consuming to achieve owing to the very large volume, thedisplacement efficiency, and/or the sweep efficiency, for example.Accordingly, in embodiments described herein, the volume of aqueoussolution injected into reservoir 105 in block 304 is preferably at leastequal to the pore volume of connate water in reservoir 105 (or portionof reservoir 105 to be loaded). The pore volume of connate water in areservoir (or portion of a reservoir to be loaded) can be calculatedusing techniques known in the art. In general, the duration of injectionin block 304 will depend on the volume of reservoir 105 to be loaded(i.e., the entire reservoir 105 vs. a portion of reservoir 105), thepermeability to water, the water saturation, and the maximum injectionpressure.

Following injection of the aqueous solution into reservoir 105 in block304, the aqueous solution forms a loaded zone extending radially outwardand longitudinally along the well(s) 120, 130 from which the aqueoussolution was injected into reservoir 105 in the same manner as loadedzone 111 previously described and shown in FIG. 3. The loaded zonedefines the volume of reservoir 105 that has had its connate waterreplaced (or at least partially replaced) with the aqueous solution. Aspreviously described, the selected chemical agents are thermallyactivated chemical species that are (1) non-decomposable orsubstantially non-decomposable and (2) non-reactive or substantiallynon-reactive in reservoir 105 below the threshold temperature. Thus, ifthe ambient reservoir temperature is below the threshold temperature,the chemical agent(s) in the aqueous solution do not substantiallydecompose, dissociate, or react with or otherwise alter the viscoushydrocarbons in reservoir 105 upon injection.

Referring again to FIG. 5, in block 305, after cold loading thereservoir 105 in block 304, the thermally activated chemical species inthe aqueous solution are thermally “activated” or “triggered.” Ingeneral, the thermally activated chemical species can be thermallyactivated or triggered by (a) the thermal energy of the reservoir 105itself if the ambient temperature of the reservoir 105 is at or abovethe threshold temperature; or (b) thermal energy added to the reservoir105 if the ambient temperature of the reservoir 105 is below thethreshold temperature. Thus, if the ambient temperature of the reservoir105 is at or above the threshold temperature of the thermally activatedchemical species, then the chemical species in the aqueous solution willbegin to decompose, dissociate, or react at the ambient temperature ofthe reservoir 105 to yield or release one or more compounds thatincrease the water wettability of the reservoir rock as described above.However, if the ambient temperature of the reservoir 105 is not at orabove the threshold temperature of the thermally activated chemicalspecies, then thermal energy is added to the reservoir 105 in block 305to a temperature equal to or greater than the threshold temperature ofthe thermally activated chemical species, thereby enabling the thermallyactivated chemical species in the aqueous solution to decompose,dissociate, or react (at an elevated temperature greater than theambient temperature of the reservoir 105) to yield or release one ormore compounds that increase the water wettability of the reservoir rockas described above.

In general, any suitable means for adding thermal energy to thereservoir 105 can be employed to raise the temperature of the reservoir105 to or above the threshold temperature of the thermally activatedchemical species. However, in embodiments described herein, thermalenergy is preferably added to the reservoir 105 in block 305 byinjecting steam into the reservoir 105 (e.g., a SAGD operation) and/orinjecting hot liquid water into the reservoir 105 (e.g., a hotwaterflooding operation).

For both hot waterflooding and steam injection to increase thetemperature of the reservoir 105 in block 305, the hot water or steam,respectively, are injected into reservoir 105 via injection well 120.Once injected into reservoir 105, the hot water or steam percolatesthrough the reservoir 105 radially outward and longitudinally alonginjection well 120, thereby forming a thermal chamber such as thermalchamber 140 shown in FIG. 4. The thermal energy from the thermal chamberraises the temperature of reservoir 105 and the loaded zone to anelevated temperature that is (i) greater than the ambient temperature ofreservoir 105, and (ii) equal to or greater than the thresholdtemperature of the thermally activated chemical species in the aqueoussolution. Once the temperature of the reservoir 105 is at or above thethreshold temperature, the thermally activated chemical species in theaqueous solution decomposes, dissociates, or reacts to yield or releasethe one or more compounds that increase the water wettability of thereservoir rock as described above. It should also be appreciated thatthe thermal energy from thermal chamber and associated elevatedtemperature reduces the viscosity of the viscous hydrocarbons inreservoir 105.

As previously described, in this embodiment, the thermally activatedchemical species selected in block 301 is (1) urea or a urea derivative,which undergo hydrolysis in aqueous solution upon thermal activation(i.e., at or above 80° C.) to produce carbon-dioxide and ammonia; or (2)a carbamate (e.g., ammonium carbamate, amine carbamate, and alkanolaminecarbamate), which undergo hydrolysis in aqueous solution upon thermalactivation (i.e., at or above 20-50° C.) to produce carbon-dioxide andat least one of ammonia, amine, and alkanolamine. The carbon-dioxide gasincreases the water wettability of the formation rock in reservoir 105.In addition, the carbon-dioxide gas increases the pressure in thereservoir 105, which offers the potential to enhance mobilization of thehydrocarbons in reservoir 105. The ammonia, amine, and alkanolamine alsoincreases the water wettability of the formation rock in reservoir 105.In addition, the ammonia, amine, and alkanolamine react with organicacid in the hydrocarbons to form surfactants in-situ, which offer thepotential to emulsify the hydrocarbons, particularly viscous oil, toform oil-in-water emulsions, thereby reducing the oil viscosity andfurther increasing the mobilization of the hydrocarbons.

In methods 200, 300, the carbon-dioxide gas, as well as the ammonia gas,amine gas, and alkanolamine gas, disperse in the aqueous solution toform foams. Since the foams comprise gas dispersed in the aqueoussolution, it is also referred to herein as “gas-in-water” foam. Thus,methods 200, 300 result in the formation of gas-in-water foams withinthe reservoir 105 (i.e., in-situ), as distinguished from the formationof gas-in-water foam outside of the reservoir, which are subsequentinjected into the reservoir. In method 200, there is nothing tostabilize the gas-in-water foams, and thus, the foams are generallyunstable and quickly collapse. However, in method 300, the mixed-wetnanoparticles stabilize the gas-in-water foams within the reservoir 105.In particular, the mixed-wet nanoparticles arrange themselves at theinterface between each gas pocket and the surrounding water—at thegas-water interfaces, the water-wet portion of the outer surface of eachnanoparticle positions itself within the water and the oil-wet portionof the outer surface of each nanoparticle positions itself outside thewater within the gas. Thus, each gas pocket is essentially surroundedand encapsulated within a plurality of the mixed-wet nanoparticles—themixed-wet outer surfaces of the nanoparticles facilitates thepositioning of the nanoparticles at the gas-water interfaces.

In method 300, the mixed-wet nanoparticles also stabilize theoil-in-water emulsions (i.e., hydrocarbons-in-aqueous solutionemulsions) resulting from the activation of the thermally activatedchemical species. In particular, the mixed-wet nanoparticles arrangethemselves at the interface between each oil droplet and the surroundingwater—at the oil-water interfaces, the water-wet portion of the outersurface of each nanoparticle positions itself within the water and theoil-wet portion of the outer surface of each nanoparticle positionsitself within the oil. Thus, each oil droplet is essentially surroundedand encapsulated within a plurality of the mixed-wet nanoparticles—themixed-wet outer surfaces of the nanoparticles facilitates thepositioning of the nanoparticles at the oil-water interfaces.

As previously described, one or more surfactant(s) can optionally beincluded in the aqueous solution formed in block 302 and injected intothe reservoir 105 in block 304. In embodiments that includesurfactant(s) in the aqueous solution, the surfactant(s) stabilize thegas-in-water foams and the oil-in-water emulsions. In addition, thesurfactant(s) function to reduce the undesirable retention ofnanoparticles on the surfaces of the surfaces of formation rock. Inparticular, the nanoparticles may be attracted to the formation rocksdue to electrostatic attraction (e.g., charged nanoparticles may beattracted to the surfaces of oppositely charged formation rocks).However, any nanoparticles retained on or adhered to the surfaces of theformation rocks are generally unavailable to stabilize the gas-in-waterfoams and oil-in-water emulsions. Consequently, retention ofnanoparticles on the surfaces of formation rock is generallyundesirable. However, surfactant(s) included in the aqueous solution atleast partially coat the formation rock surfaces, thereby reducingand/or preventing the adherence of the nanoparticles on the surfaces ofthe formation rocks. Surfactant(s) functioning to coat the formationrock surfaces are generally sacrificial since they are no longeravailable to help stabilize the gas-in-water foams and the oil-in-wateremulsions. Accordingly, lower cost surfactant(s) may be preferred.

Referring again to FIG. 5, a soaking period can optionally be employedafter thermally activating the chemical agent(s) in block 305 and beforewaterflooding in block 306 to provide ample time for thereaction/decomposition products of the chemical agent(s) to interactwith the formation rock and hydrocarbons in the reservoir 105. Inembodiments where a soaking period is employed, the soaking period ispreferably between 1 and 30 days. In other embodiments, no soakingperiod is employed, and method 300 proceeds immediately from block 306to block 306.

Referring still to FIG. 5, after thermally activating the thermallyactivated chemical species, a waterflooding operation is performed inblock 306. The waterflooding operation in block 306 is the same as thewaterflooding operation in block 206 of method 200 previously described.Namely, the waterflooding operation in block 306 can be a cold or hotwaterflooding operation. In addition, the water is injected underpressure into the reservoir 105 through injection well 120. The waterincreases the pressure in reservoir 105, and as the water moves throughthe reservoir 105, it displaces hydrocarbons from the pore spaces. Thehydrocarbon displacement is enhanced in embodiments described herein bythe increase in the water wettability of the reservoir 105 resultingfrom the thermal activation of the thermally activated chemical species.In particular, waterflooding of the treated reservoir 105 in block 306after treatment of the reservoir 105 in block 305 leads to “beading” and“rolling up” of the hydrocarbons in reservoir 105 that are attached torock/formation surfaces. The resulting hydrocarbon droplets are moreeasily pushed or swept by the water through the reservoir 105 and intoproduction well 130. The hydrocarbons and any water collected inproduction well 130 are produced to the surface via natural flow orartificial lift (i.e., with or without artificial lift) according toblock 307.

In general, the waterflood operation in block 206 can be performed usingany suitable type of water. In embodiments described herein, the waterused for the waterflood operation (e.g., in block 206) preferably has acomposition (e.g., salt concentration and composition) that does notdamage the formation rock in reservoir 105. In general, this can bedetermined by performing injectivity tests with core samples recoveredfrom reservoir 105 using methods known in the art. In addition, inembodiments described herein, the water used in the waterfloodingoperation preferably has its salinity (i.e., dissolved solids and ioniccontent) tailored and adjusted as described, for example, in U.S. Pat.Nos. 7,987,907 and 8,439,111, each of which is incorporated herein byreference in its entirety. In some embodiments, the water injected toperform the waterflood in block 306 has a total dissolved solids (TDS)greater than 200 ppm and less than 5,000 ppm. In other embodiments, thewater used in the waterflooding operation (e.g., in block 206) comprisesa brine with a relatively low multivalent cation content and a totaldissolved solids (TDS) less than or equal to 50,000 ppm. For example, insome such embodiments, the multivalent cation content is less than 300ppm, alternatively less than 100, or alternatively less than 50 ppm. Itshould be appreciated that the water used for the waterflooding canoptionally include polymer(s), polymer pre-cursor(s), delayed actionpolymer(s), or combinations thereof. Further, the waterflood operationin block 206 can optionally be performed by cyclically injecting waterfollowed by gas such as part of a Water Alternated with Gas (WAG)operation.

The gas-in-water foams stabilized by the nanoparticles in embodiments ofmethod 300 offer the potential to enhance production. In particular,during conventional waterflooding operations, water channels can form inthe reservoir between the injection and production well. These waterchannels define preferential paths for the injected water to flowthrough the reservoir from the injection well to the production well.The hydrocarbons disposed within the water channels are swept andcarried to the production well, however, hydrocarbons outside the waterchannels are generally left behind in the formation. Since such waterchannels and associated preferential paths decrease the volume of thereservoir swept by the injected water, they undesirably result inreduced production. However, in embodiments of method 300 describedherein, the gas-in-water foams stabilized by the nanoparticles haveviscosities greater than the viscosity of the injection water and fillwater channels in the reservoir. Consequently, the gas-in-water foamsforce at least some of the injected water outside of the water channels,thereby effectively increasing the volume of the reservoir 105 swept bythe waterflooding operation, which offers the potential for increasedproduction in block 307.

The oil-in-water emulsions stabilized by the nanoparticles inembodiments of method 300 also offer the potential to enhanceproduction. In particular, the oil-in-water emulsions decrease theviscosity of the hydrocarbons in the reservoir, thereby enhancingmobilization of the hydrocarbons during the waterflooding operation inblock 306.

In the manner described, embodiments described herein (e.g., system 10and methods 200, 300) can be employed to produce hydrocarbons, includinglight oil, medium oil, and viscous oil (e.g., bitumen and heavy oil) ina subterranean reservoir. Although such embodiments can be used torecover and produce hydrocarbons having any viscosity under ambientreservoir conditions, it is particularly suited for the recovery andproduction of viscous hydrocarbons having an API gravity less than 30°under ambient reservoir conditions.

In FIGS. 2 and 5, blocks 201-207 and 301-307, respectively, are shown asbeing performed once. However, blocks 204-207 and 304-307 of methods200, 300, respectively, (i.e., loading the reservoir 105, thermallyactivating the chemical agent(s), conducting a waterflooding operation,and producing hydrocarbons) can be repeated in a cyclical fashion tofurther enhance production and the ultimate quantity of hydrocarbonsrecovered. In addition, any one or more of blocks 201-207 and 301-307can be performed more than once to enhance hydrocarbon production. Forexample, during blocks 306, 307 of method 300, water channels definingpreferential paths for the water injected during block 306 may form,potentially reducing hydrocarbon production. The gas-in-water foamsstabilized by the nanoparticles in method 300 force at least some of theinjected water outside of the water channels to increase the volume ofthe reservoir 105 swept by the waterflooding operation, thereby offeringthe potential to increase production in block 307. To continue and/orincrease the in-situ formation of gas-in-water foams to maintain and/orincrease the volume of the reservoir 105 swept by the waterfloodingoperation, block 304, 305 can be repeated in parallel with blocks 306,307 (i.e., repeat blocks 304, 305 simultaneous with performance ofblocks 306, 307), or alternatively, blocks 304-307 can be repeated inseries (i.e., repeat blocks 304-307 one after the other as shown in FIG.5).

In embodiments of methods 200, 300 shown in FIGS. 2 and 5, respectively,the reservoir 105 is treated with the aqueous solution in blocks 204,205 and blocks 304, 305, respectively, prior to conducting thewaterflooding operation in block 206, 306, respectively. However, inother embodiments, the reservoir (e.g., reservoir 105) is treated (i.e.,the reservoir is cold loaded with the aqueous solution and the thermallyactivated chemical species is thermally activated) after one or morewaterflooding operation(s). In such embodiments, treatment of thereservoir following a waterflooding operation offers the potential to atleast partially close and reduce water channels formed in the reservoirduring the previous waterflooding operation. For example, in oneembodiment, a previously waterflooded reservoir is treated with anaqueous solution including one or more thermally activated chemicalagents and nanoparticles (optionally with surfactant(s)) as describedherein with respect to method 300. Next, the thermally activatedchemical agents are thermally activated by (a) the thermal energy of thereservoir itself if the ambient temperature of the reservoir is at orabove the threshold temperature; or (b) thermal energy added to thereservoir 105 if the ambient temperature of the reservoir 105 is belowthe threshold temperature.

In embodiments where the thermally activated chemical species is urea, aurea derivative, or carbamate, the carbon-dioxide gas resulting from thethermal activation increases the water wettability of the formation rockin reservoir 105. In addition, the carbon-dioxide gas increases thepressure in the reservoir 105, which offers the potential to enhancemobilization of the hydrocarbons in reservoir 105. The ammonia, amine,and alkanolamine resulting from the thermal activation also increasesthe water wettability of the formation rock in reservoir 105. Inaddition, the ammonia, amine, and alkanolamine react with organic acidin the hydrocarbons to form surfactants in-situ, which offer thepotential to emulsify the hydrocarbons, particularly viscous oil, toform oil-in-water emulsions, thereby reducing the oil viscosity andfurther increasing the mobilization of the hydrocarbons. Still further,as previously described, the carbon-dioxide gas, as well as the ammonia,amine, and alkanolamine gas, disperse in the aqueous solution to formgas-in-water foams in-situ, which are stabilized by the mixed-wetnanoparticles and any optional surfactant(s) included in the aqueoussolution. The oil-in-water emulsions formed via surfactants (surfactantsformed in-situ and/or optional surfactants in the aqueous solution) arealso stabilized by the mixed-wet nanoparticles and any optionalsurfactant(s) included in the aqueous solution. Any optionalsurfactant(s) included in the aqueous solution can reduce theundesirable retention of nanoparticles on the surfaces of the surfacesof formation rock. The gas-in-water foams formed in-situ fill the waterchannels in the reservoir formed during the previous waterfloodingoperation.

After thermally activating the thermally activated chemical species, awaterflooding operation is performed (a cold or hot waterfloodingoperation). The water increases the pressure in reservoir, and as thewater moves through the reservoir, it displaces hydrocarbons from thepore spaces. The hydrocarbon displacement is enhanced by the increase inthe water wettability of the formation rock in the reservoir. Inaddition, the gas-in-water foams stabilized by the nanoparticles offerthe potential to enhance production by filling water channels andforcing at least some of the injected water outside of the waterchannels, thereby effectively increasing the volume of the reservoirswept by the waterflooding operation. Still further, the oil-in-wateremulsions stabilized by the nanoparticles in embodiments offer thepotential to enhance production by decreasing the viscosity of thehydrocarbons in the reservoir.

Although methods 200, 300 shown in FIGS. 2 and 5, respectively, aredescribed in the context of well system 10 including injection andproduction wells 120, 130 for producing hydrocarbons in subterraneanreservoir 105, in general, embodiments of methods described herein(e.g., methods 200, 300) can be used in connection with other types ofrecovery techniques. For example, embodiments described herein can beused to separate, strip, and recover hydrocarbons from rock. In oneembodiment, the rock including hydrocarbons are treated with an aqueoussolution including one or more thermally activated chemical agents aspreviously described with respect to methods 200, 300. Next, thethermally activated chemical agents are activated by adding thermalenergy to the treated rock to increase the temperature of the treatedrock to or above the threshold temperature of the thermally activatedchemical species in the aqueous solution. In embodiments where thethermally activated chemical species is urea, a urea derivative, or acarbamate, the carbon-dioxide gas resulting from the thermal activationincreases the water wettability of the rock. The ammonia, amine, andalkanolamine resulting from the thermal activation also increase thewater wettability of the rock. In addition, the ammonia, amine, andalkanolamine react with organic acid in the hydrocarbons to formsurfactants in-situ, which offer the potential to emulsify thehydrocarbons, particularly viscous oil, to form oil-in-water emulsions,thereby reducing the oil viscosity and further increasing themobilization of the hydrocarbons.

After thermally activating the thermally activated chemical species(e.g., urea), the treated rock is flushed or washed with cold water,which displaces hydrocarbons from the rock. The hydrocarbon displacementis enhanced by the increase in the water wettability of the treated rockresulting from the thermal activation of the thermally activatedchemical species. In particular, the water leads to “beading” and“rolling up” of the hydrocarbons in the rock that are attached to rocksurfaces. The resulting hydrocarbon droplets are more easily pushed orswept by the water from the rock, thereby separating and stripping thehydrocarbons from the rock.

In other embodiments, the rock including hydrocarbons are treated withan aqueous solution including one or more thermally activated chemicalagents and nanoparticles (optionally with surfactant(s)) as describedherein with respect to method 300. Next, the thermally activatedchemical agents are activated by adding thermal energy to the treatedrock to increase the temperature of the treated rock to or above thethreshold temperature of the thermally activated chemical species in theaqueous solution. In embodiments where the thermally activated chemicalspecies is urea, a urea derivative, or a carbamate, the carbon-dioxidegas resulting from the thermal activation increases the waterwettability of the rock. The ammonia, amine, and alkanolamine resultingfrom the thermal activation also increase the water wettability of therock. In addition, the ammonia, amine, and alkanolamine react withorganic acid in the hydrocarbons to form surfactants in-situ, whichoffer the potential to emulsify the hydrocarbons, particularly viscousoil, to form oil-in-water emulsions, thereby reducing the oil viscosityand further increasing the mobilization of the hydrocarbons. In the samemanner as previously described, the mixed-wet nanoparticles in theaqueous solution stabilize the gas-in-water foams, as well as theoil-in-water emulsions (i.e., hydrocarbons-in-aqueous solutionemulsions) formed in the rock. In addition, any optional surfactant(s)included in the aqueous solution help stabilize the gas-in-water foamsand the oil-in-water emulsions in the rock, as well as reduce theundesirable retention of nanoparticles on the surfaces of the surfacesof rock.

After thermally activating the thermally activated chemical species, thetreated rock is flushed or washed with cold water, which displaceshydrocarbons from the rock. The hydrocarbon displacement is enhanced bythe increase in the water wettability of the treated rock resulting fromthe thermal activation of the thermally activated chemical species. Inparticular, the water leads to “beading” and “rolling up” of thehydrocarbons in the rock that are attached to rock surfaces. Theresulting hydrocarbon droplets are more easily pushed or swept by thewater from the rock, thereby separating and stripping the hydrocarbonsfrom the rock. In addition, the gas-in-water foams and oil-in-wateremulsions stabilized by the nanoparticles offer the potential to enhancerecovery of the hydrocarbons from the rock. In particular, thegas-in-water foams stabilized by the nanoparticles have viscositiesgreater than the viscosity of the water used to flush the and fill waterchannels in the rock. Consequently, the gas-in-water foams force atleast some of the water outside of the water channels, therebyeffectively increasing the volume of the rock swept by the water, whichoffers the potential for increased production. The oil-in-wateremulsions stabilized by the nanoparticles decrease the viscosity of thehydrocarbons in the rock, thereby enhancing mobilization of thehydrocarbons when the rock are flushed with water. A soaking period canoptionally be employed after thermally activating the chemical agent(s)before flushing/washing the rock with water to provide ample time forthe reaction/decomposition products of the chemical agent(s) to interactwith the hydrocarbons in the rock. In embodiments where a soaking periodis employed, the soaking period is preferably between 1 and 30 days. Inother embodiments, no soaking period is employed, and the rock isflushed/washed with water immediately after thermally activating thechemical agent(s).

To further illustrate various illustrative embodiments disclosed herein,the following examples are provided.

EXAMPLE 1

Certain thermally activated chemical species, as described above, inaqueous solution undergo a hydrolysis reaction upon heating (i.e.,thermal activation) and produce gas(es) and/or liquid(s). The productionof gas(es) upon thermal activation of such thermally activated chemicalspecies loaded into the formation increase the pressure within theformation and enhance the mobilization of hydrocarbons in the formation.Urea is one exemplary thermally activated chemical species thatundergoes hydrolysis in aqueous solution upon thermal activation toproduce carbon-dioxide and ammonia. The carbon-dioxide and ammonia existin equilibrium between the gas and liquid phases. Experiments wereconducted to analyze the thermal activation of urea and the associatedhydrolysis. Each experiment was carried out in a stainless steel reactorvessel having a total cell volume of ˜400 cm³. A Teflon® liner wasinstalled in the vessel to avoid any reactions between stainless steelwall and aqueous solution comprising urea. A series of pressuretransducers were set up for measuring the pressure within the reactorvessel during each experiment. To achieve a stable temperature, thereactor vessel was placed in an oven.

For each experiment, a sample of approximately 60 cm³ of an aqueoussolution comprising urea at predetermined concentration (5 wt % urea, 10wt % urea, 15 wt % urea, and 20 wt % urea) was weighed (i.e., the weightof the 60 cm³ of aqueous solution comprising the urea was determined)and fed into the reactor vessel. The air in the reactor vessel wasreplaced with nitrogen (N₂) gas at 10 psig. The oven temperature wasthen gradually increased to a specific, predetermined target temperature(50° C., 80° C., 100° C., and 150° C.), and then kept at the targettemperature for an extended period of time until little to no pressureincrease within the reactor vessel was observed (i.e., approaching theequilibrium pressure). Next, the reactor was allowed to cool to ambienttemperature, and then the concentration of urea, dissolvedcarbon-dioxide (CO₂) and ammonia (NH₃) in the water, and carbon-dioxide(CO₂) in the gas phase were determined.

As a baseline for comparison purposes, and to investigate whether anyhydrolysis of urea occurred at 10° C., bottles of aqueous solutions ofurea at predetermined concentrations (10 wt % urea) were kept at 10° C.in a refrigerator for 8 months, and then the concentrations of ureadissolved carbon-dioxide (CO₂) and ammonia (NH₃) in the water, andcarbon-dioxide (CO₂) in the gas phase were determined.

FIG. 6 illustrates the wt % of urea reacted as a function of temperature(at 10° C., 50° C., 100° C., and 150° C.) when samples of aqueoussolutions, each comprising 10 wt % of urea were heated (to 50° C., 100°C., and 150° C.) in the reactor vessel in the manner previouslydescribed. The experimental results shown in FIG. 6 indicated that thehydrolysis of urea in aqueous solution strongly depends on thetemperature, and further, that the hydrolysis of urea in aqueoussolution can be thermally triggered when the aqueous solution is heatedup to above approximately 50° C.

Table 1 below illustrates the measured equilibrium pressure within thereactor vessel and the wt % of urea reacted (via hydrolysis) whensamples of aqueous solutions having different concentrations of urea (5wt % urea, 10 wt % urea, 15 wt % urea, and 20 wt % urea) were heated to150° C. in the manner as previously described. The experimental resultsshown in Table 2 indicated that the increase in pressure (the differencebetween the equilibrium/final pressure and the initial 10 psig pressure)due to reaction of urea (via hydrolysis) was strongly dependent on theurea concentration—the greater the urea concentration in the aqueoussolution, the greater the increase in pressure. In addition, theexperimental results shown in Table 1 indicated that all orsubstantially all of the urea in the aqueous solution was reacted (viahydrolysis).

TABLE 1 Urea Concentration in Aqueous Solution Sample Pressure IncreaseWt % of (wt %) (psi) Urea Reacted 5 72.8 100.0 10 135.5 99.6 15 184.398.1 20 234.7 98.0

Table 2 below illustrates the wt % of urea reacted (via hydrolysis), thevolumes of gas(es) produced by the reaction of urea, and the timeallowed for the reaction when samples of aqueous solutions havingdifferent concentrations of urea (5 wt %, 10 wt %, 15 wt %, and 20 wt %)were heated (to 50° C., 80° C., 100° C., and 150° C.) in the mannerpreviously described. The experimental results shown in Table 2indicated that urea is very stable in aqueous solution at ambienttemperatures, and further, that the hydrolysis of urea in aqueoussolution does not occur until the aqueous solution is heated to acertain temperature. For instance, the sample of aqueous solutionincluding urea at a concentration of 10 wt % was heated to 50° C. forseveral days and no gas was produced. The sample of aqueous solutionincluding urea at a concentration of 10 wt % maintained at 10° C. for 8months exhibited no reactions of urea (i.e., no reduction in ureaconcentration was found).

TABLE 2 Urea Concentration Volume of in Aqueous Produced Gas Solution Wt% at Standard Time Allowed Sample Temperature Urea Conditions⁴ for (wt%) (° C.) Reacted (cm³) Reaction⁵ 10 10 0 0 8 months 10 50 0 0 70 hours10 80 6 104 18 days 5 100 14 120 120 hours 10 100 22 363 158 hours 5 150100 864 30 hours 10 150 100 1620 40 hours 15 150 98 2208 36 hours 20 15098 2886 7.5 hours ⁴“Standard Conditions” are 273 K and 1 bar (absolute).⁵Experiments with urea wt % decompositions less than 100% were stoppedarbitrarily on the grounds of time and were not necessarily indicativeof equilibrium.

EXAMPLE 2

Experiments were conducted to assess the effect of the treatment ofsynthetic oilsands with urea on oil recovery. In particular, syntheticoilsand samples having different amounts of original oil, referred to asoriginal oil-in-place (OIP), were treated with steam. Select samples ofsynthetic oilsands having 10% original OIP were treated with acombination of steam and different concentrations of urea. One syntheticoilsand sample treated with steam having a 5 wt % urea concentration wasflushed with cold water to simulate a cold waterflooding operation. Theamount of oil recovered from each synthetic oilsand sample was measured.

FIG. 7 illustrates the percentage of oil recovered from each syntheticoilsand sample as a function of the original OIP and the steamcomposition. In general, the results indicate that the oil recovery bysteam strongly depends on the original OIP. When the original OIP was10%, the oil recovery from the synthetic oilsand sample treated withsteam (without any urea) was essentially zero. However, when urea wasadded to the steam, the oil recovery from the synthetic oilsand samplewith 10% original OIP increased with urea concentration. For example, a10% original OIP synthetic oilsand sample treated with steam comprising10 wt % urea increased the oil recovery to about 5%. Further, for the10% original OIP synthetic oilsand sample that was treated with steamcomprising 10 wt % urea and then flushed with cold water, the oilrecovery increased significantly to about 30%. When the cold water wasapplied to that synthetic oilsand sample after treatment with steamcomprising 10 wt % urea, the “roll-up” phenomenon was observed as shownin FIG. 8. The “roll-up” of the oil in this sample indicated the sandsurface had become strongly water wet, thereby suggesting that thewettability change by the urea treatment might be a mechanism for thesignificantly improved oil recovery.

While preferred embodiments have been shown and described, modificationsthereof can be made by one skilled in the art without departing from thescope or teachings herein. The embodiments described herein areexemplary only and are not limiting. Many variations and modificationsof the systems, apparatus, and processes described herein are possibleand are within the scope of the invention. For example, the relativedimensions of various parts, the materials from which the various partsare made, and other parameters can be varied. Accordingly, the scope ofprotection is not limited to the embodiments described herein, but isonly limited by the claims that follow, the scope of which shall includeall equivalents of the subject matter of the claims. Unless expresslystated otherwise, the steps in a method claim may be performed in anyorder. The recitation of identifiers such as (a), (b), (c) or (1), (2),(3) before steps in a method claim are not intended to and do notspecify a particular order to the steps, but rather are used to simplifysubsequent reference to such steps.

What is claimed is:
 1. A method for producing hydrocarbons within areservoir in a subterranean formation, the reservoir having an ambienttemperature and an ambient pressure, the method comprising: (a)injecting an aqueous solution into the reservoir with the reservoir atthe ambient temperature, wherein the aqueous solution comprises waterand a thermally activated chemical species, wherein the thermallyactivated chemical species is urea, a urea derivative, or a carbamate,wherein the thermally activated chemical agent is thermally activated ator above a threshold temperature less than 200° C.; (b) thermallyactivating the thermally activated chemical species in the aqueoussolution during or after (a) at a temperature equal to or greater thanthe threshold temperature to produce carbon-dioxide and at least one ofammonia, amine, and alkanolamine within the reservoir; (c) increasing awater wettability of the subterranean formation in response to thethermally activation in (b); and (d) waterflooding the reservoir withwater after (a), (b) and (c).
 2. The method of claim 1, wherein thethermally activated chemical species is a urea derivative selected fromthe group comprising methyl urea, 1-ethyl urea, 1,1-dimethyl urea,1,3-dimethyl urea, 1,1-diethyl urea, and bi(hydroymethyl) urea.
 3. Themethod of claim 1, wherein the thermally activated chemical species is acarbamate selected from the group comprising ammonium carbamate, aminecarbamate, and alkanolamine carbamate.
 4. The method of claim 1, whereinthe thermally activated chemical species is a carbamate having asolubility of at least 0.05 g/ml in aqueous solution.
 5. The method ofclaim 1, wherein the thermally activated chemical species is a carbamatehaving the formula R₁R₂NC(O)₂R₃, where R₁, R₂, R₃ is each selected froma C1-C2 alkyl group, a C1-C2 alkanol group, a phenyl group, a benzylgroup, hydroxyl, or hydrogen.
 6. The method of claim 5, wherein thecarbamate is ethyl carbamate or ethanolamine carbamate.
 7. The method ofclaim 1, wherein (b) comprises injecting steam or hot liquid water intothe reservoir to increase the temperature of the reservoir to atemperature that is equal to or greater than the threshold temperature.8. The method of claim 1, wherein the threshold temperature is between20° and 150° C.
 9. The method of claim 1, wherein the thresholdtemperature is less than the ambient temperature of the reservoir, andwherein (b) comprises thermally activating the thermally activatedchemical species at the ambient temperature of the reservoir.
 10. Themethod of claim 9, wherein the ambient temperature of the reservoir isgreater than 80° C.
 11. The method of claim 1, wherein the aqueoussolution is injected at an injection pressure during (a) that is lessthan a displacement pressure of the hydrocarbons in the reservoir. 12.The method of claim 1, wherein (c) comprises increasing the waterwettability of the subterranean formation with the carbon-dioxide,ammonia, amine, or alkanolamine.
 13. The method of claim 12, furthercomprising: increasing the pressure of the reservoir with thecarbon-dioxide; reacting the ammonia, amine, or alkanolamine withorganic acids in the hydrocarbons to form surfactants in the reservoir,wherein the surfactants emulsify the hydrocarbons and form anoil-in-water emulsion in the reservoir.
 14. The method of claim 13,wherein the aqueous solution comprises a plurality of nanoparticles, andwherein each nanoparticle has an outer surface that is partiallywater-wet and partially oil-wet.
 15. The method of claim 14, wherein amajority of the total outer surface area of each nanoparticle iswater-wet.
 16. The method of claim 14, further comprising: forming agas-in-water foam in the reservoir with carbon dioxide gas; stabilizingthe oil-in-water emulsion in the reservoir with the nanoparticles; andstabilizing the gas-in-water foam in the reservoir with thenanoparticles.
 17. The method of claim 14, wherein each nanoparticle hasa size or diameter between 1.0 nanometer and 1.0 micron; and wherein theaqueous solution has a concentration of nanoparticles between 10 and10,000 ppmw.
 18. The method of claim 14, wherein each nanoparticlecomprises an inorganic or polymeric material.
 19. The method of claim18, wherein the outer surface of each nanoparticle is partially coatedwith a coating.
 20. The method of claim 14, wherein the aqueous solutionfurther comprises one or more surfactants configured to reduce adhesionof the nanoparticles to surfaces of the subterranean formation.
 21. Themethod of claim 1, further comprising repeating (a) to (d).
 22. Themethod of claim 1, wherein (d) comprises performing a hot waterfloodingoperation by injecting water having a temperature greater than theambient temperature of the reservoir into the reservoir or performing acold waterflooding operation by injecting water having a temperatureless than or equal to the ambient temperature of the reservoir into thereservoir.
 23. The method of claim 1, further comprising waterfloodingthe reservoir before (a) to (d).
 24. The method of claim 1, wherein theaqueous solution has a temperature less than or equal to 40° C. during(a).
 25. The method of claim 1, wherein the thermally activated chemicalspecies is urea.
 26. The method of claim 25, wherein the aqueoussolution has a temperature less than or equal to 40° C. during (a). 27.The method of claim 1, wherein the water for waterflooding the reservoirin (d) comprises a total dissolved solids (TDS) greater than 200 ppm andless than 5,000 ppm.
 28. The method of claim 1, wherein the water forwaterflooding the reservoir in (d) comprises a multivalent cationcontent less than 300 ppm.
 29. The method of claim 1, wherein the waterfor waterflooding the reservoir in (d) comprises a polymer, a polymerpre-cursor, or a delayed action polymer.
 30. The method of claim 1,further comprises: (e) injecting gas into the reservoir after (d); and(f) waterflooding the reservoir with water after (e).